Systems and Methods for the Production of a Subterranean Reservoir Containing Viscous Hydrocarbons

ABSTRACT

A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation includes (a) injecting steam into the reservoir. In addition, the method includes (b) injecting a surfactant into the reservoir with the steam during (a). Further, the method includes (c) decreasing the viscosity of the hydrocarbons in the reservoir with thermal energy from the steam. Still further, the method includes (d) emulsifying the hydrocarbons with the surfactant during (b) and (c). Moreover, the method includes (e) mobilizing at least some of the hydrocarbons in the reservoir.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/789,371 filed Mar. 15, 2013, and entitled “Systems and Methods for the Production of a Subterranean Reservoir Containing Viscous Hydrocarbons,” which is hereby incorporated herein by reference in its entirety. This application claims benefit of U.S. provisional patent application Ser. No. 61/789,484 filed Mar. 15, 2013, and entitled “Systems and Methods for the Production of a Subterranean Reservoir Containing Viscous Hydrocarbons,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The invention relates generally to thermal recovery techniques for producing viscous hydrocarbons such as heavy oil and bitumen. More particularly, the invention relates to the treatment of viscous hydrocarbons to accelerate production therefrom with thermal recovery techniques.

As existing reserves of conventional light liquid hydrocarbons (e.g., light crude oil) are depleted and prices for hydrocarbon products continue to rise, there is a push to find new sources of hydrocarbons. Viscous hydrocarbons such as heavy oil and bitumen offer an alternative source of hydrocarbons with extensive deposits throughout the world. In general, hydrocarbons having an API gravity less than 22° are referred to as “heavy oil” and hydrocarbons having an API gravity less than 10° are referred to as “bitumen.” Although recovery of heavy oil and bitumen present challenges due to their relatively high viscosities, there are a variety of processes that can be employed to recover such viscous hydrocarbons from underground deposits.

Many techniques for recovering heavy oil and bitumen utilize thermal energy to heat the hydrocarbons, decrease the viscosity of the hydrocarbons, and mobilize the hydrocarbons within the formation, thereby enabling the extraction and recovery of the hydrocarbons. Accordingly, such production and recovery processes may generally be described as “thermal” techniques. A steam-assisted gravity drainage (SAGD) operation is one thermal technique for recovering viscous hydrocarbons such as bitumen and heavy oil.

SAGD operations typically employ two vertically spaced horizontal wells drilled into the reservoir and located close to the bottom of the reservoir. Steam is injected into the reservoir through an upper, horizontal injection well, referred to as the injection well, to form a “steam chamber” that extends into the reservoir around and above the horizontal injection well. Thermal energy from the steam reduces the viscosity of the viscous hydrocarbons in the reservoir, thereby enhancing the mobility of the hydrocarbons and enabling them to flow downward through the formation under the force of gravity. The mobile hydrocarbons drain into the lower horizontal well, also referred to as the production well. The hydrocarbons are collected in the production well and are produced to the surface via artificial lift.

The commissioning of a SAGD well pair requires communication between the injection well and the production well. Typically, this is achieved by steam circulation or “bullheading” of steam, provided the formation is sufficiently permeable to water. The objective of both techniques is to heat and mobilize the viscous hydrocarbons in the zone between the well-pair to allow pressure communication from the injection well to the production well. This commissioning processes can be time consuming (e.g., often takes more than three months), which results in high costs and delays the ultimate production of oil.

The application of steam in SAGD operations for the recovery of viscous hydrocarbons relies primarily on the transfer of thermal energy from the steam to the hydrocarbons to enhance mobility through the formation via decreased viscosity. However, in many cases, the heating and mobilization of the hydrocarbons is not uniform owing to local variations in permeability, porosity and wettability, which may result in a protracted start-up and poor initial conformance of the steam chamber. Limitations on the temperature and pressure of the steam injected in SAGD operations (e.g., due to the reservoir being shallow, poor caprock integrity, etc.) can also lengthen start-up and negatively affect initial conformance of the steam chamber.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure. In an embodiment, the method comprises (a) selecting a pretreatment agent that is water-soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir. In addition, the method comprises (b) forming an aqueous pretreatment solution with the pretreatment agent. Further, the method comprises (c) injecting the aqueous pretreatment solution into the reservoir at a temperature less than or equal to the ambient temperature of the reservoir. Still further, the method comprises (d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).

These and other needs in the art are addressed in another embodiment by a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure. In an embodiment, the method comprises (a) forming a SAGD well pair extending through the formation. The SAGD well pair includes an injection well and a production well. Each well has a vertical section extending from the surface of the formation and a horizontal section traversing the reservoir. In addition, the method comprises (b) forming an aqueous pretreatment solution with one or more pretreatment agents. Each pretreatment agent is water-soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir. Further, the method comprises (c) injecting the aqueous pretreatment solution into the reservoir at a temperature less than or equal to the ambient reservoir temperature. Still further, the method comprises (d) injecting steam into the reservoir after (c) to increase the temperature of the reservoir to a SAGD operating temperature.

These and other needs in the art are addressed in another embodiment by a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure. In an embodiment, the method comprises (a) selecting one or more pretreatment agents. Each pretreatment agent is water-soluble and non-reactive or substantially non-reactive in the reservoir at the ambient temperature of the reservoir. In addition, the method comprises (b) mixing the one or more pretreatment agents with a brine to form an aqueous pretreatment solution. Each pretreatment agent in the aqueous pretreatment solution has a concentration greater than or equal to 0.01 wt % and less than the solubility limit of the pretreatment agent in the brine. Further, the method comprises (c) determining a volume of the reservoir to be pretreated and determining a pore volume of the connate water in the portion of the reservoir to be treated. Still further, the method comprises (d) injecting a volume of the aqueous pretreatment solution into the reservoir at the ambient reservoir temperature. The volume is at least equal to the pore volume of the connate water in the portion of the reservoir to be pretreated.

These and other needs in the art are addressed in another embodiment by a method for recovering viscous hydrocarbons from a reservoir in a subterranean formation. In an embodiment, the method comprises (a) injecting steam into the reservoir. In addition, the method comprises (b) injecting a surfactant into the reservoir with the steam during (a). Further, the method comprises (c) decreasing the viscosity of the hydrocarbons in the reservoir with thermal energy from the steam. Still further, the method comprises (d) emulsifying the hydrocarbons with the surfactant during (b) and (c). Moreover, the method comprises (e) mobilizing at least some of the hydrocarbons in the reservoir.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic cross-sectional side view of an embodiment of a system in accordance with the principles described herein for pretreating and producing viscous hydrocarbons from a subterranean formation;

FIG. 2 is a schematic cross-sectional end view of the system of FIG. 1 taken along section II-II of FIG. 1;

FIG. 3 is a graphical illustration of an embodiment of a method in accordance with the principles described herein for pretreating and producing viscous hydrocarbons in the reservoir of FIG. 1 using the system of FIG. 1;

FIG. 4 is a schematic cross-sectional end view of the system of FIG. 1 taken along section II-II of FIG. 1 illustrating a pretreatment zone formed by injecting a pretreatment aqueous solution into the reservoir of FIG. 1 according to the method of FIG. 3; and

FIG. 5 is a schematic cross-sectional end view of the system of FIG. 1 taken along section II-II of FIG. 1 illustrating a steam chamber formed by injecting steam into the reservoir of FIG. 1 according to the method of FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. Any reference to up or down in the description and the claims will be made for purposes of clarity, with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the borehole and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation.

Referring now to FIGS. 1 and 2, an embodiment of a system 10 for pretreating and producing viscous hydrocarbons (e.g., bitumen and heavy oil) using a thermal recovery technique is shown. In particular, in this embodiment, system 10 is configured to employ steam-assisted gravity drainage (SAGD) thermal recovery techniques to produce generally immobile, viscous hydrocarbons dispersed throughout a reservoir 100 in a subterranean formation 101. Reservoir 100 is vertically positioned between an overburden layer 102 and an underburden layer 103. Layers 102, 103 are formed of generally impermeable formation material (e.g., rock).

System 10 includes an injection well 20 extending from the surface 104 and a production well 30 extending from the surface 104 generally parallel to injection well 20. Each well 20, 30 extends through overburden layer 102 and includes an uphole end 20 a, 30 a, respectively, disposed at the surface 104, a downhole end 20 b, 30 b, respectively, disposed in formation 101, a generally vertical section 21, 31, respectively, extending into the formation 101 from the surface 104, and a horizontal section 22, 32, respectively, extending horizontally through reservoir 100. Horizontal sections 22, 32 are both positioned proximal the bottom of reservoir 100 and above underburden layer 103, with section 32 of production well 30 located below section 22 of injection well 20. In addition, horizontal sections 22, 32 are lined with perforated or slotted liners, and thus, are both open to reservoir 100.

Referring now to FIG. 3, an embodiment of a method 200 for producing viscous hydrocarbons (e.g., heavy oil and/or bitumen) from reservoir 100 (or portion of reservoir 100) using system 10 is shown. In this embodiment, viscous hydrocarbons in reservoir 100 are pretreated with one or more pretreatment agents prior to commissioning SAGD well pair 20, 30. As will be described in more detail below, such pretreatment offers the potential to decrease the time for commissioning SAGD well pair 20, 30 and/or increase start-up quality through improved conformance, thereby accelerating production from well 30.

Beginning in block 201 of method 200, one or more pretreatment agents for injection into reservoir 100 are selected. The purpose of the pretreatment agent(s) is to enhance initial mobility of the hydrocarbons in reservoir 100 during the start-up/commissioning of the SAGD well pair 20, 30, and thus, selection of the particular pretreatment agent(s) is based, at least in part, on its ability to enhance the mobility of the hydrocarbons in the particular formation of interest (e.g., reservoir 100 in formation 101). In general, the ability of a pretreatment agent to enhance the mobility of hydrocarbons depends on a variety of factors including, without limitation, the type of formation, its oil saturation, water saturation, the native phase permeability to water, its wettability, physical and chemical properties of the oil, etc. Core and/or oil samples from the formation of interest can be tested with various pretreatment agents to facilitate the selection in block 201. Each selected pretreatment agent is preferably water soluble such that it can be injected into reservoir 100 in an aqueous solution as will be described in more detail below. The cost and availability of various pretreatment agent(s) may also impact the selection in block 201.

Although a variety of chemical additives may be useful as pretreatment agents, in embodiments described herein, each pretreatment agent selected in block 201 is a surfactant or a thermally activated chemical species. Each selected pretreatment agent can be used alone (e.g., surfactant alone or thermally activated chemical species alone), with one or more other pretreatment agents (e.g., surfactant in combination with a thermally activated chemical species, multiple surfactants, multiple thermally activated chemical species), with one or more other chemical additives (e.g., surfactant in combination with another chemical, thermally activated chemical species in combination with another chemical, etc.), or combinations thereof.

Each surfactant selected for use as a pretreatment agent in block 201 is an emulsifier that is generally unable to emulsify immobile hydrocarbons in reservoir 100, but capable of emulsifying hydrocarbons in reservoir 100 once they become mobile. In general, bitumen (e.g., bitumen of the Canadian Oil Sands of Alberta) is immobile at ambient reservoir temperatures, and must be heated to a temperature of at least 50° to 80° C. to be converted into mobile hydrocarbons within reservoir 100. Thus, for example, each surfactant selected as a pretreatment agent in block 201 is unable to emulsify immobile bitumen at ambient reservoir temperatures, but capable of emulsifying bitumen once it is warmed to at least 50° to 80° C. and converted to mobile hydrocarbons. Examples of suitable surfactants that can be selected as a pretreatment agent in bock 201 include, without limitation, branched alcohol propoxylated sulfates (APS) (e.g., Alfoterra® series surfactants available from Sasol North American Inc. of Houston, Tex.); internal olefin sulfonates (e.g., Petrostep® series surfactants available from Stepan Chemical Company of Northfield, Ill.); branched alpha olefin sulfonates (e.g. Bio-Terge® series surfactants available from Stepan Chemical Company of Northfield, Ill.); polyoxyethylene alkyl phenyl ether (e.g. Triton X-100™ available from The DOW Chemical Company of Midland, Mich.); sodium/potassium oleate; and gemini (dimeric) surfactants.

Each thermally activated chemical species selected for use as a pretreatment agent in block 201 is a chemical species that is non-reactive or substantially non-reactive in reservoir 100 at ambient reservoir temperatures, but decompose at a temperature above the ambient reservoir temperature and below the operating temperature of the thermal recovery process employed to produce reservoir 100 to form one or more of (a) a gas or gases; (b) an alkaline compound or compounds, which can react with naturally occurring acids in hydrocarbon reservoir to form surfactant-like compounds; (c) a compound miscible with hydrocarbons to some extent; (d) a compound that controls the wettability of solid surfaces; or (e) combinations thereof. As used herein, the phrase “substantially non-reactive” refers to a chemical species that has a conversion rate of less than 10% over a 24 hour period in an aqueous solution, as prepared according to block 202 described in more detail below, and in the presence of hydrocarbons in a reservoir at the ambient reservoir temperature. For most reservoirs containing viscous hydrocarbons and most thermal recovery processes (e.g., SAGD, steam flooding, cyclic steam stimulation (CSS), electric reservoir heating operations, etc.), each thermally activated chemical species selected as pretreatment agent in block 201 preferably decomposes at a temperature between 40° and 200° C., and more preferably between 80° and 150° C. For example, the typical ambient reservoir temperature in the Canadian Oil Sands is about 8° to 12° C., and the typical operating temperature of a SAGD thermal recovery process is 180° to 220° C. Thus, each thermally activated chemical species selected as a pretreatment agent in block 201 for viscous hydrocarbons in the Canadian Oil Sands to be produced using SAGD is a chemical species that is non-reactive or substantially non-reactive in the Canadian Oil Sands between 8° and 12° C. (i.e., at ambient reservoir temperatures), but decompose at a temperature above 8° and 12° C. (i.e., the ambient reservoir temperature) and below 180° to 220° (i.e., the operating temperature of the SAGD thermal recovery process). Examples of suitable thermally activated chemical species that can be selected as a pretreatment agent in bock 201 include, without limitation, urea, bicarbonates (e.g. sodium bicarbonate, etc.); and oxalates (e.g., ammonium oxalate.).

Moving now to block 202, the selected pretreatment agent(s) is/are mixed with a brine (i.e., solution of salt in water) to form an aqueous pretreatment solution. The brine preferably has a salt concentration and composition analogous to that of reservoir 100 to reduce the potential for the aqueous pretreatment solution to negatively alter the reservoir 100. The salt concentration and composition of the reservoir 100 can be determined from core samples. In general, an aqueous pretreatment solution is preferred as water is generally mobile within a reservoir comprising viscous hydrocarbons such as heavy oil and bitumen (e.g., reservoir 100). The concentration of each pretreatment agent in the aqueous pretreatment solution can be varied depending on a variety of factors, but is preferably at least about 0.01 wt % and less than or equal to the solubility limit of the pretreatment agent in the brine at the ambient temperature of reservoir 100.

Referring still to FIG. 3, in block 203, the injection parameters for the aqueous pretreatment solution are determined. The injection parameters include, without limitation, the pressure, the temperature, and the flow rate at which the aqueous pretreatment solution will be injected into reservoir 100. The injection pressure of the aqueous pretreatment solution is preferably sufficiently high enough to enable injection into reservoir 100 (i.e., the pressure is greater than or equal to the ambient pressure of reservoir 100), and less than the fracture pressure of overburden 102, the fracture pressure of reservoir 100 (if one exists), and the pressure at which hydrocarbons in reservoir 100 will be displaced. The temperature of the chemical additive(s) in aqueous solution is preferably at or below the ambient temperature of reservoir 100.

Referring still to FIG. 3, moving now to block 204, the aqueous pretreatment solution is injected into the reservoir 100 according to the injection parameters determined in block 203. Since the aqueous pretreatment solution is injected prior to commissioning SAGD well pair 20, 30 in block 205, and is not heated or injected with steam, but rather, is injected into reservoir 100 at or below the ambient temperature of reservoir 100, injection of the aqueous pretreatment solution according to block 204 may be referred to herein as “cold” pretreatment of reservoir 100.

Since SAGD well pair 20, 30 are not yet commissioned, and thus, are not injecting steam and collecting hydrocarbons, respectively, during the cold pretreatment in block 204, the aqueous pretreatment solution can be injected into reservoir 100 utilizing one or both wells 20, 30. The aqueous pretreatment solution is preferably injected into reservoir 100 via injection well 20 alone, via both wells 20, 30 at the same time, or via both wells 20, 30 at the same time followed by injection well 20 alone. In addition, the aqueous pretreatment solution can be intermittently injected or pulsed by controllably varying the injection pressure within an acceptable range of pressures as determined in block 203. Pulsing the injection pressure of the aqueous pretreatment solution offers the potential to enhance distribution of the aqueous pretreatment solution in reservoir 100 and facilitate dilation of reservoir 100. In cases where production well 30 is not employed for injection, production well 30 is preferably maintained at a pressure lower than the ambient pressure of reservoir 100 (e.g., with a pump) to create a driving force for the migration of fluids into production well 30. Pumping fluids out of production well 30 to maintain the lower pressure also enables chemical analysis and monitoring of the fluids flowing into production well 30 from the surrounding formation 101, which can provide insight as to the migration of the aqueous pretreatment solution through reservoir 100 and the saturation of reservoir 100 with the aqueous pretreatment solution. In general, any of these injection options can be performed alone or in combination with other injection options.

Injection of the aqueous pretreatment solution in block 204 is performed until reservoir 100 (or portion of reservoir 100 to be pretreated) is sufficiently charged. Ideally, the aqueous pretreatment solution is injected into reservoir 100 until the total pore volume in reservoir 100 (or portion of reservoir 100 to be pretreated) available for water is filled with the aqueous pretreatment solution. However, practically, this may be extremely difficult, costly, and/or time consuming to achieve. Accordingly, in embodiments described herein, the volume of aqueous pretreatment solution injected into reservoir 100 in block 204 is preferably at least equal to the pore volume of connate water in reservoir 100 (or portion of reservoir 100 to be pretreated) and more preferably about two times the pore volume of connate water in reservoir 100 (or portion of reservoir 100 to be pretreated). In general, the pore volume of connate water in a reservoir (or portion of a reservoir) can be calculated using known techniques.

In general, the duration of injection in block 204 will depend on the volume of reservoir 100 to be pretreated (i.e., the entire reservoir 100 vs. a portion of reservoir 100), the native phase permeability to water and the displacement efficiency. Injection of the aqueous pretreatment solution in block 204 is preferably performed as close to possible to commissioning in block 205 described in more detail below to minimize and/or avoid natural dispersion of the aqueous pretreatment solution outside of the portion of reservoir 100 into which they were injected under pressure in block 204. For most applications, injection of the aqueous pretreatment solution in block 204 is preferably performed for 1 to 50 days, and more preferably from 1 to 14 days.

Referring briefly to FIG. 4, reservoir 100 and formation 101 are shown following injection of the aqueous pretreatment solution according to block 204. In FIG. 4, the aqueous pretreatment solution is represented with reference numeral 110. The injected aqueous pretreatment solution 110 forms a pretreatment zone 111 extending radially outward and longitudinally along the portion of horizontal section(s) 22, 32 from which the pretreatment solution 110 was injected into reservoir 100. Pretreatment zone 111 defines the volume of reservoir 100 that has had its connate water replaced with the aqueous pretreatment solution 110.

As previously described, the selected pretreatment agents are thermally activated chemical species that are non-reactive or substantially non-reactive in reservoir 100 at the ambient reservoir temperature and/or surfactants unable to emulsify immobile hydrocarbons in reservoir 100 at the ambient reservoir temperature, and further, the selected pretreatment agents are injected into reservoir 100 at the ambient reservoir temperature in block 204. Thus, the pretreatment agent(s) in the aqueous pretreatment solution do not substantially react with or alter the viscous hydrocarbons in reservoir 100 upon injection. It should be appreciated that this is in contrast to chemical compounds that are designed to or inherently react with or alter the hydrocarbons in a reservoir at ambient reservoir temperatures, which may generally be described as “preconditioning” the reservoir. As used herein, chemical compounds that react with or alter the hydrocarbons in a reservoir at the ambient reservoir temperature are referred to as “preconditioning” agents; whereas chemical compounds that are non-reactive or substantially non-reactive in a reservoir at ambient reservoir temperature, or unable to emulsify immobile hydrocarbons in a reservoir at the ambient reservoir temperature (e.g., pretreatment agents selected in block 201), are referred to as “pretreatment” agents.

Referring again to FIG. 3, once reservoir 100 (or the portion of reservoir 100 being pretreated) is sufficiently charged with the aqueous pretreatment solution according to block 204, the SAGD well pair 20, 30 is commissioned in block 205. As previously described, to limit and/or avoid the natural dispersion of the aqueous pretreatment solution out of reservoir 100, commissioning in block 205 is preferably performed immediately after injection in block 204. In general, commissioning SAGD well pair 20, 30 is performed by injecting steam through injection well 20 and production well 30 in either circulation or “bullheading” modes until appropriate pressure communication between wells 20, 30 is achieved. Then, injection of steam into production well 30 is ceased, while steam continues to be injected through injection well 20.

Referring briefly to FIG. 5, the steam and associated hot water percolate through reservoir 100, thereby forming a steam chamber 120 that extends horizontally outward and vertically upward from horizontal section 22 of injection well 20. Steam chamber 120 is generally shaped like an inverted triangular prism that extends along and upward from the full length of horizontal section 22. Thermal energy from steam chamber 120 increases the temperature of reservoir 100. This reduces the viscosity of the viscous hydrocarbons in reservoir 100 to a sufficient extent to mobilize at least a portion of the hydrocarbons in reservoir 100. In addition, thermal energy from steam chamber 120 increases the temperature of reservoir 100 and pretreatment zone 111 to an operating temperature sufficient to “activate” the pretreatment agent(s) in the aqueous pretreatment solution (i.e., increase the temperature of reservoir 100 to an operating temperature sufficient to mobilize hydrocarbons in reservoir 100, thereby allowing surfactant(s) in the aqueous pretreatment solution to emulsify the hydrocarbons in reservoir 100 and/or to a temperature sufficient to decompose the thermally activated chemical specie(s) in the aqueous pretreatment solution). The activation of the pretreatment agent(s) in the aqueous pretreatment solution offers the potential to enhance mobilization of hydrocarbons in reservoir 100 both prior to the arrival of steam chamber 120 (e.g., in response to the thermal front that moves ahead of the edge of steam chamber 120) and after the arrival of the steam chamber 120.

Referring again to FIG. 3, in block 206, steam continues to be injected through injection well 20 as the mobilized hydrocarbons in reservoir 100 drain under gravity through reservoir 100 and formation 101 into horizontal section 32. Artificial lift is employed to produce hydrocarbons collected in production well 30 to the surface 102.

One or more surfactants can be injected with steam during startup and in block 205 and/or injected with steam during production operations in block 206. More specifically, one or more surfactants can be injected with steam during startup in block 205 and/or injected with steam during production operations in block 206 with or without pretreating reservoir 100 according to blocks 201-204. For injecting one or more surfactants with steam, the injected steam preferably comprises both a vapor phase and liquid phase. The liquid phase in the injected steam provides a medium to carry the one or more surfactants injected with the steam to reservoir 100. Each surfactant injected with steam in block 205 and/or block 206 is preferably an emulsifier of mobile hydrocarbons in reservoir 100. As previously described, bitumen (e.g., bitumen of the Canadian Oil Sands of Alberta) is immobile at ambient reservoir temperatures, and must be heated to a temperature of at least 50° to 80° C. to be converted into mobile hydrocarbons within reservoir 100. Thus, for example, any surfactant(s) injected with steam in block 205 and/or block 206 is preferably capable of emulsifying bitumen once it is warmed to at least 50° to 80° C. and converted to mobile hydrocarbons. Examples of suitable surfactants that can be injected with steam in block 205 and/or block 206 include, without limitation, the surfactants previously described that are suitable for selection as pretreatment agent(s) in block 201—i.e., branched alcohol propoxylated sulfates (APS) (e.g., Alfoterra® series surfactants available from Sasol North American Inc. of Houston, Tex.); internal olefin sulfonates (e.g., Petrostep® series surfactants available from Stepan Chemical Company of Northfield, Ill.); branched alpha olefin sulfonates (e.g. Bio-Terge® series surfactants available from Stepan Chemical Company of Northfield, Ill.); polyoxyethylene alkyl phenyl ether (e.g. Triton X-100™ available from The DOW Chemical Company of Midland, Mich.); sodium/potassium oleate; and gemini (dimeric) surfactants.

The conventional approach to commissioning a SAGD well pair via injection of steam (without prior pretreatment) to begin mobilization of viscous hydrocarbons and allow fluid communication between the SAGD well pair may take several months. During this lengthy startup period before production of hydrocarbons, money and resources are being invested into the SAGD operations. In embodiments described herein, the injection of an aqueous pretreatment solution into the reservoir (e.g., reservoir 100) prior to injection of steam offers the potential to accelerate subsequent commissioning of the SAGD well pair (e.g., SAGD well pair 20, 30).

In the manner described, embodiments described herein (e.g., system 10 and method 200) are employed to produce viscous hydrocarbons in a subterranean reservoir. Although such embodiments can be used to recover and produce heavy oil having an API gravity less than 22°, it is particularly suited for the recovery and production of viscous hydrocarbons having an API gravity less than about 12°. In addition, although pretreatment method 200 shown in FIG. 3 is described in the context of well system 10 including SAGD well pair 20, 30, in general, embodiments of pretreatment methods described herein (e.g., method 100) can be used in connection with other types of thermal recovery technique for viscous hydrocarbons such as steam flooding, cyclic steam stimulation (CSS), electric reservoir heating operations, etc.

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps. 

What is claimed is:
 1. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising: (a) selecting a pretreatment agent that is water-soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir; (b) forming an aqueous pretreatment solution with the pretreatment agent; (c) injecting the aqueous pretreatment solution into the reservoir at a temperature less than or equal to the ambient temperature of the reservoir; and (d) adding thermal energy to the reservoir to increase the temperature of the reservoir to an operating temperature after (c).
 2. The method of claim 1, wherein (d) is performed immediately after (c).
 3. The method of claim 1, wherein the aqueous pretreatment solution is injected at an injection pressure during (c); wherein that the injection pressure is greater than the ambient pressure of the reservoir and below a fracturing pressure of the formation.
 4. The method of claim 3, wherein that the injection pressure is less than a displacement pressure of the viscous hydrocarbons in the reservoir.
 5. The method of claim 3, further comprising pulsing the injection pressure during (c).
 6. The method of claim 1, wherein the pretreatment agent is a surfactant or a thermally activated chemical species that activates at an activation temperature greater than the ambient temperature of the reservoir temperature and less than the operating temperature.
 7. The method of claim 6, wherein the activation temperature is between 40° and 200° C.
 8. The method of claim 7, wherein the pretreatment agent is urea.
 9. The method of claim 1, wherein (b) comprises: (b1) determining a salt concentration and a salt composition in the reservoir; (b2) forming a brine having a salt concentration and a salt composition analogous to the salt concentration and the salt composition of the reservoir; (b3) mixing the pretreatment agent and the brine.
 10. The method of claim 1, wherein (d) comprises injecting steam into the reservoir.
 11. The method of claim 10, wherein (d) comprises injecting steam and a surfactant into the reservoir at the same time.
 12. The method of claim 1, wherein (c) comprises injecting the aqueous pretreatment solution into the reservoir through a first well extending through the reservoir or through the first well and a second well extending through the reservoir.
 13. The method of claim 1, wherein (a) comprises selecting a plurality of pretreatment agents, wherein each pretreatment agent is water-soluble and inert at the ambient temperature of the reservoir; and wherein (b) comprises forming the aqueous pretreatment solution with the plurality of pretreatment agents.
 14. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising: (a) forming a SAGD well pair extending through the formation, wherein the SAGD well pair includes an injection well and a production well, wherein each well has a vertical section extending from the surface of the formation and a horizontal section traversing the reservoir; (b) forming an aqueous pretreatment solution with one or more pretreatment agents, wherein each pretreatment agent is water-soluble and substantially non-reactive in the reservoir at the ambient temperature of the reservoir; (c) injecting the aqueous pretreatment solution into the reservoir at a temperature less than or equal to the ambient reservoir temperature; and (d) injecting steam into the reservoir after (c) to increase the temperature of the reservoir to a SAGD operating temperature.
 15. The method of claim 14, wherein (c) comprises: (c1) pumping the aqueous pretreatment solution through the horizontal section of the production well and the horizontal section of the injection well at the same time.
 16. The method of claim 15, wherein (c) further comprises: (c2) pumping the aqueous pretreatment solution through the horizontal section of the production well after (c1).
 17. The method of claim 14, wherein (c) comprises injecting the aqueous solution at a pressure that is greater than the ambient pressure of the reservoir and below a fracturing pressure of the formation.
 18. The method of claim 17, further comprising varying the pressure of the aqueous solution during (c).
 19. The method of claim 14, wherein (d) comprises: (d1) decreasing the viscosity of the hydrocarbons in the reservoir with thermal energy from the steam; (d2) decomposing the pretreatment agent with thermal energy from the steam; (d3) mobilizing at least some of the hydrocarbons in the reservoir during (d1) and (d2).
 20. The method of claim 19, further comprising: collecting mobilized hydrocarbons in the horizontal section of the production well; and producing the collected hydrocarbons in the production well to the surface.
 21. The method of claim 14, wherein (d) is performed immediately after (c).
 22. The method of claim 14, wherein the pretreatment agent is a surfactant or a thermally activated chemical species that activates at an activation temperature greater than the ambient temperature of the reservoir temperature and less than the SAGD operating temperature.
 23. The method of claim 22, wherein the activation temperature is between 40° and 200° C.
 24. The method of claim 14, wherein at least one of the one or more pretreatment agents is urea.
 25. The method of claim 14, further comprising injecting a surfactant into the reservoir with the steam during (d).
 26. The method of claim 20, further comprising injecting a surfactant into the reservoir with steam while producing the collected hydrocarbons in the production well to the surface.
 27. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the reservoir having an ambient temperature and an ambient pressure, the method comprising: (a) selecting one or more pretreatment agents, wherein each pretreatment agent is water-soluble and non-reactive or substantially non-reactive in the reservoir at the ambient temperature of the reservoir; (b) mixing the one or more pretreatment agents with a brine to form an aqueous pretreatment solution, wherein each pretreatment agent in the aqueous pretreatment solution has a concentration greater than or equal to 0.01 wt % and less than the solubility limit of the pretreatment agent in the brine; (c) determining a volume of the reservoir to be pretreated and determining a pore volume of the connate water in the portion of the reservoir to be treated; and (d) injecting a volume of the aqueous pretreatment solution into the reservoir at the ambient reservoir temperature, wherein the volume is at least equal to the pore volume of the connate water in the portion of the reservoir to be pretreated.
 28. The method of claim 27, wherein (d) comprises injecting the aqueous pretreatment solution at a pressure that is greater than the ambient pressure of the reservoir and less than a fracture pressure of the formation.
 29. The method of claim 27, wherein the volume of the injected aqueous pretreatment solution is about two times the pore volume of the connate water in the portion of the reservoir to be pretreated.
 30. The method of claim 27, further comprising: increasing the temperature of the reservoir to a thermal recovery operating temperature; wherein the pretreatment agent is a surfactant or a thermally activated chemical species that activates at an activation temperature greater than the ambient temperature of the reservoir temperature and less than the thermal recovery operating temperature.
 31. The method of claim 30, wherein the activation temperature is between 40° and 200° C.
 32. The method of claim 30, wherein at least one of the one or more pretreatment agents is urea.
 33. A method for recovering viscous hydrocarbons from a reservoir in a subterranean formation, the method comprising: (a) injecting steam into the reservoir; (b) injecting a surfactant into the reservoir with the steam during (a); (c) decreasing the viscosity of the hydrocarbons in the reservoir with thermal energy from the steam; (d) emulsifying the hydrocarbons with the surfactant during (b) and (c); and (e) mobilizing at least some of the hydrocarbons in the reservoir.
 34. The method of claim 33, further comprising: (f) collecting mobilized hydrocarbons in the horizontal section of the production well; and (g) producing the collected hydrocarbons in the production well to the surface.
 35. The method of claim 34, further comprising injecting the surfactant into the reservoir with the steam during (a) before (g) or during (g).
 36. The method of claim 33, further comprising: (a) forming a SAGD well pair extending through the formation, wherein the SAGD well pair includes an injection well and a production well, wherein each well has a vertical section extending from the surface of the formation and a horizontal section traversing the reservoir; wherein (a) comprises injecting steam into the reservoir from the horizontal section of the injection well; wherein (b) comprises injecting the surfactant into the reservoir from the horizontal section of the injection well. 